U.S. patent number 8,640,771 [Application Number 11/855,945] was granted by the patent office on 2014-02-04 for determination of coal bed natural gas production factors and a system to determine same.
This patent grant is currently assigned to Gas Sensing Technology Corp.. The grantee listed for this patent is Daniel Buttry, Rick Cox, John M. Pope. Invention is credited to Daniel Buttry, Rick Cox, John M. Pope.
United States Patent |
8,640,771 |
Pope , et al. |
February 4, 2014 |
Determination of coal bed natural gas production factors and a
system to determine same
Abstract
Well fluids in coalbed natural gas reservoirs and other
carbonaceous reservoirs are analyzed to determine production
factors such as gas content, critical desorption pressure, and/or
other reservoir and operational variables. In particular, the
partial pressure of methane or a predictor substance, or a methane
concentration, are measured and/or determined for the wells and
production factors are determined therefrom.
Inventors: |
Pope; John M. (Laramie, WY),
Cox; Rick (Laramie, WY), Buttry; Daniel (Tempe, AZ) |
Applicant: |
Name |
City |
State |
Country |
Type |
Pope; John M.
Cox; Rick
Buttry; Daniel |
Laramie
Laramie
Tempe |
WY
WY
AZ |
US
US
US |
|
|
Assignee: |
Gas Sensing Technology Corp.
(Laramie, WY)
|
Family
ID: |
36992368 |
Appl.
No.: |
11/855,945 |
Filed: |
September 14, 2007 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20120227960 A1 |
Sep 13, 2012 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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PCT/US2006/009087 |
Mar 14, 2006 |
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60661152 |
Mar 14, 2005 |
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Current U.S.
Class: |
166/250.01;
166/264; 166/250.17 |
Current CPC
Class: |
E21B
43/006 (20130101); G01V 9/007 (20130101); E21B
47/10 (20130101); E21B 49/087 (20130101) |
Current International
Class: |
E21B
47/06 (20120101); E21B 47/00 (20120101) |
Field of
Search: |
;166/250.01,250.17,264 |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
International Search Report for PCT/US06/009087, mailed Nov. 6,
2006. cited by applicant .
Written Opinion of the International Search Authority for
PCT/US06/009087, mailed Nov. 6, 2006. cited by applicant.
|
Primary Examiner: Wright; Giovanna
Attorney, Agent or Firm: McEwing; David
Parent Case Text
CROSS REFERENCE TO RELATED APPLICATIONS
This application is a continuation of International Application No.
PCT/US2006/009087, filed Mar. 14, 2006 and entitled "Determination
of Coal Bed Natural Gas Production Factors and a System to
Determine Same," which claims priority to U.S. Provisional Patent
Application No. 60/661,152, filed Mar. 14, 2005 and entitled
"Determination of Coal Bed Natural Gas Production Factors and a
System to Determine Same," both of which are hereby incorporated by
reference in their entireties.
Claims
What is claimed is:
1. A method of determining a production factor for a carbonaceous
material reservoir, the method comprising: providing a well in a
carbonaceous material reservoir; providing unsampled fluid at a
depth in the well; placing a sensor adjacent the unsampled fluid
and performing a measurement on the unsampled fluid; using data
from the measurement to determine a partial pressure of a solution
gas in the carbonaceous material reservoir; and determining a
production factor for the carbonaceous material reservoir from the
partial pressure of the solution gas.
2. The method of claim 1, wherein the carbonaceous material
reservoir is a coalbed methane well and the solution gas is methane
or other substance indicative of methane.
3. The method of claim 2, wherein the unsampled fluid is wellbore
fluid that is at equilibrium with reservoir fluid in the
carbonaceous material reservoir.
4. The method of claim 2, wherein the unsampled fluid is reservoir
fluid extracted from the carbonaceous material reservoir.
5. The method of claim 2, wherein the production factor is selected
from the group consisting of critical desorption pressure of
methane, coal gas content, material gas content, dewatering time,
and an amount of reserves present in the formation.
6. The method of claim 2, wherein the partial pressure is
determined via measurement of a concentration of methane dissolved
in the fluid.
7. The method of claim 1, wherein the carbonaceous material
reservoir has a coal seam and the unsampled fluid is measured at a
depth in the well close to the coal seam.
8. The method of claim 1, wherein performing a measurement on the
unsampled fluid includes: transporting the unsampled fluid from
said depth in the well to the surface of the well without
collecting a discrete sample of the fluid or substantially altering
the fluid properties of said unsampled fluid; and passively
measuring the unsampled fluid using the sensor at the surface.
9. The method of claim 1, wherein the partial pressure is selected
from the group consisting of: a partial pressure of methane in the
fluid; a partial pressure of nitrogen in the fluid, and a partial
pressure of carbon dioxide in the fluid.
10. The method of claim 1, wherein the step of determining of the
partial pressure is selected from the group consisting of:
determining a concentration of methane in a well fluid, determining
a concentration of methane in a reservoir fluid, and combinations
thereof.
11. The method of claim 1, wherein the step of determining the
partial pressure includes correlating a partial pressure of the
solution gas to a partial pressure of methane in the reservoir.
12. The method of claim 1, wherein the step of determining the
partial pressure includes correlating a partial pressure of a
reservoir fluid to a partial pressure of methane in the
reservoir.
13. The method of claim 1, wherein the step of determining the
partial pressure includes correlating the concentration of methane
to the partial pressure.
14. The method of claim 1, wherein the step of placing a sensor
includes placing a concentration sensor.
15. The method of claim 1, wherein the step of placing a sensor
includes placing a partial pressure sensor.
16. The method of claim 1, wherein the step of placing a sensor
includes placing an optical spectrometer.
17. The method of claim 1, wherein the step of placing a sensor
includes placing a Raman spectrometer.
18. The method of claim 1, wherein the step of performing a
measurement on the unsampled fluid comprises observing a depth at
which methane cavitates from well fluid and determining the fluid
pressure at said observed depth.
19. A method of determining a production factor for a coal bed
methane well, the method comprising: providing a well in a coal bed
reservoir; providing unsampled fluid at a depth in the well;
measuring the pressure of the unsampled fluid; measuring a
concentration or partial pressure of methane or another substance
indicative of a partial pressure of methane in the unsampled fluid;
and correlating the concentration or partial pressure to a gas
content of the coal bed reservoir or a critical desorption pressure
of the coal bed methane well.
20. The method of claim 19, wherein the correlating is adjusted to
account for a non-equilibrium between the unsampled fluid and
reservoir fluid.
21. A system for determining a production factor of a coalbed
methane well, the system comprising: a sensor capable of measuring
a partial pressure of gas in a coal bed methane well wherein the
gas is in unsampled well fluid or the concentration of gas in the
unsampled well fluid; a temperature, conductivity and/or pressure
transducer to measure temperature, conductivity and/or pressure of
the fluid at the measurement point; a correlator, adjusted for
temperature, conductivity and/or pressure of the fluid at the
measurement point, to correlate the concentration of gas in the
fluid to the partial pressure of the gas in the fluid; and a
correlator to correlate the partial pressure of the gas in the
fluid to a production factor of the coal seam.
22. The system of claim 21, wherein the partial pressure sensor
includes an Raman spectrometer.
Description
BACKGROUND OF THE INVENTION
1. The Field of the Invention
The present invention relates to a method and system of determining
gas content, dewatering time, critical desorption pressure, and/or
other reservoir and operational variables, referred to as
production factors, for coalbed natural gas wells. The present
invention also relates to determining these production factors for
other carbonaceous material reservoir wells including carbonaceous
shale, shales, tight sands, and muddy sands or other methane
reservoirs wherein the methane is at least partially dissolved in
water within the reservoir. In particular, this invention relates
to a method and system for measuring a partial pressure of methane
or a predictor substance for a coalbed natural gas reservoir and
determining production factors therefrom.
2. The Relevant Technology
With reference to FIG. 1, a typical completed coalbed natural gas
well includes a borehole which is drilled to at least a depth of a
coal seam. During drilling and completion of the well an initial
borehole is drilled to or through one or more coal seams and a
casing is set to at least the top of the lowest coal seam. Each
coal seam of interest is then accessed from the wellbore either by
perforating holes from the wellbore into the coal seam, or by open
hole completion of the wellbore at the lowest coal seam. In many
cases the wellbore contains water which originates from one or more
layers of the geological strata, including some coal seams, through
which the borehole is drilled, or that may be residual from the
drilling and completion process. In many instances the coal seams
of interest are wet which means that the coal contains water in at
least some portion of the coal seam. In some cases the coal seams
can be dry or partially dry which means that the coal seam has no
or limited amounts of water. In some cases, coal seams are
stimulated or otherwise treated using techniques such as
fracturing, acid treatment, recirculation of water, and other known
methods.
Typically, production of methane is initiated by pumping fluid from
the well to reduce the pressure on the coal seam. This fluid
typically contains dissolved methane, termed "solution gas." When
the overall hydrostatic pressure of the well at the depth of the
coal seam is lowered to the critical desorption pressure of the
methane contained within the coal seam, further reductions in
pressure lead to off-gassing of methane. At this point the well is
considered to be in production. When a well is pre-production, the
primary fluid flow through the reservoir is condensed phase,
typically water. When a well is in production, both gas and
condensed phase fluid flow through the reservoir, typically in
competition. Gas flow is due to expansion of the gas after it
devolves from the coal. Condensed phase fluid flow is due to
continued pumping of that fluid from the wellbore throughout most
of the life of the well. In some cases, for wells that have been
substantially dewatered and that have little or no hydrostatic
pressure remaining, reduced pressure systems, e.g. vacuums, may be
installed to further reduce the reservoir pressure and devolve and
produce further gas.
Depending upon the reservoir conditions and the coal type,
formations, depth and other geological characteristics, fluid from
a well may need to be pumped for a very short time (e.g. not at
all, if overpressurized with gas) or for a very long time (e.g. up
to four years or longer for severely gas undersaturated or low
permeability coals) in order to reach production. The life of the
well during which it produces economical amounts of methane, and
the amount of gas that is produced during that time, also varies
depending on the amount of methane entrained, contained, adsorbed
or otherwise present in the coal bed. In certain circumstances the
life of a well may be up to 30 years or longer.
Traditionally, coal bed methane production factors have been
determined by a variety of methods. One known method of determining
the critical pressure which the well must reach in order to produce
methane by off-gassing involves retrieval of a core sample of the
coal, transportation of the core sample to a laboratory setting,
and quantification of the amount of methane contained within the
sample coal via gas desorption. As seen in FIG. 2, this quantity is
then analyzed to determine the coal gas content and compared to an
adsorption isotherm of the same or a similar coal in order to
determine the critical desorption pressure of the coalbed
reservoir. The isotherm of the coal or coal gas content curve
represents the amount of methane the coal may contain depending
upon the pressure. More particularly, the sample of the coal from
the reservoir itself is subjected to reduced pressure over time to
measure the amount of methane which it contained. To this
measurement is added a "lost gas" estimation to account for gas
that issued from the coal sample during retrieval. The total amount
of methane is then plotted on the isotherm chart and a correlation
is made to the ideal curve. Where the saturation gas curve and
measured gas content intersect is the critical pressure which must
be reached by pumping in order for the well to produce methane.
Other factors may be deduced from this plot or map. Unfortunately,
this process is expensive, time consuming, and error-prone.
BRIEF SUMMARY OF THE INVENTION
An aspect of certain preferred embodiments of the invention
provides that a production factor such as gas content, dewatering
time, critical desorption pressure, and/or other reservoir and
operational variables can be determined via measurement or
determination of methane partial pressure or another substance or
substances indicative of the methane partial pressure.
Those skilled in the art will recognize that reference to a partial
pressure of gas dissolved in a fluid is related to the amount of
that gas that is dissolved in that fluid and that would be in
equilibrium with a vapor phase in contact with that fluid. Use of
the term "partial pressure of gas in fluid" is meant to encompass,
but not be limited to, related terms such as concentration,
effective density, quantity, potential volume, potential pressure,
and amount.
The critical desorption pressure of the coal bed methane reservoir
or coal seam is equal to the methane partial pressure of the
reservoir or coal seam. By determining the effective methane
partial pressure of the coal, reservoir fluid or well fluid the
critical desorption pressure may be determined. If the system is in
physical and chemical equilibrium the partial pressures of methane
for the reservoir, coal, reservoir fluid and well fluid are all
equal. However, in practice this is not always the case as many
variables may affect the partial pressures and their interrelation
to one another. In such cases other measurements or determinations
may be used to correlate the partial pressures.
Other production factors may be determined utilizing the partial
pressure of methane via correlation, modeling, calculation, and
other sensor data.
The measurement of the partial pressure of methane can be
accomplished via measurement of a dissolved methane concentration.
Preferably, the measurement of the concentration is done at a depth
of the coal seam and as near to the coal seam as possible so that
other variables and effects are lessened. This concentration is
then correlated to a partial pressure of methane of the well fluid,
reservoir fluid or coal reservoir. The partial pressure of methane
within the coal reservoir is then used to determine the critical
desorption pressure along with a gas content of the coal reservoir,
dewatering time and other reservoir and operational variables.
The measurement or determination of the partial pressure may also
be accomplished in other ways such as by direct measurement of the
partial pressure via instrumentation or another variable which
correlates to the partial pressure of methane.
In a preferred embodiment, the methane concentration or another
substance's concentration dissolved in a coal seam reservoir fluid
is measured at a depth in the well at or near the coal seam of
interest. This concentration is then correlated to a partial
pressure of methane in the fluid. This partial pressure of methane
in the fluid is then correlated to the partial pressure of methane
in the reservoir which equates to the critical desorption
pressure.
In certain preferred embodiments of the invention a method for
determining a production factor or gas content of a coal seam is
achieved by direct measurement of methane concentration of the
wellbore fluid. This measurement in combination with a known or
determined solubility property for methane in water allows the
calculation of the partial pressure of methane in the wellbore
fluid.
If the fluid in the wellbore is in equilibrium with the reservoir
fluid, which in turn is in equilibrium with the coal seam itself,
the hydrologic and physical connection between these fluids and the
coal allows that the measurement of one of these partial pressures
can be correlated into a measurement of the other two. The partial
pressure of the fluids is controlled by the amount of methane
present in the coal seam. More simply stated; when more methane is
present in a particular coal seam, the partial pressure of methane
in the fluids is higher.
The methane partial pressure of the coal seam is the critical
desorption pressure, which is the saturation point of the coal seam
at that pressure. Dewatering of the well acts to lower the total
fluid pressure to a value at or below the critical desorption
pressure, which causes devolution of methane out of the coal seam
as free gas.
Having determined the critical desorption pressure, by further
utilizing an isotherm of the interested coal seam calculations can
be made to determine the gas content of the coal seam and estimate
the total methane reserves. As well, the critical desorption
pressure can be compared to the rate of decrease of the total
reservoir pressure during dewatering, the rate of flow of water
from the coal seam, and other reservoir and operational variables,
in order to predict dewatering time, permeability, and other
production factors.
The concentration of the methane or other substance or the partial
pressure of methane in the reservoir fluid may be measured by
optical spectrometers, membrane-covered semiconductor sensors, mass
spectrometers or the like.
The concentration which is measured may be directly correlated to a
partial pressure of methane in the reservoir or any intermediate
quantity that is relatable to the amount of methane in the fluid or
parts of the fluid. Each coal seam has unique properties which may
affect the correlations. By using an intermediate correlation these
properties may be used to enhance the accuracy and precision of the
partial pressure determination of the methane in the reservoir.
The production factors which may be determined are gas partial
pressure, percent saturation of gas in coal, gas content, bookable
reserves, permeability, porosity, relative permeability, critical
desorption pressure, dewatering time, solution gas, stage of
production, cone of depression, cross-seam water and gas flow,
water salinity, identification of contributing seams and
formations, density, coal friability, cleat and fracture structure
including size, distribution and orientation, dewatering area and
volume, degassing area and volume, gas concentration, reservoir
pressure, gas recovery factor, gas-in-place, water and gas
production rates and timetables, well lifetime, optimum well
spacing, optimum production procedures including choice of which
seams in multizone wells and which wells in a pod should be
produced first, second, etc., optimum completion procedures
including choice of which seams and wells to complete first,
second, etc., which to abandon or sell, and how to complete and
produce the desired wells, effectiveness of prior completion and
production activities, indication of regions and seams of favorable
production potential, and other production factors which will be
apparent to those skilled in the art.
Another aspect of the invention is an apparatus and/or system which
measures the partial pressure of methane or another substance
indicative of the methane or measures a precursor variable such as
the concentration of methane to allow or produce a determination of
the methane partial pressure of the reservoir. The system may
include a pressure transducer. The pressure transducer can measure
the total pressure of the fluid at the measurement point. The
transducer can also measure a gas pressure down a wellbore when the
methane is evolved from the water.
Preferably, the concentration or partial pressure is measured by
Raman spectroscopy. This may be accomplished by lowering a probe or
housing within the well which contains the spectrometer or parts
thereof or by guiding a radiation from a radiation source into the
well and onto the fluid at or near the coal seam from the
spectrometer located outside of the well. Characteristic radiation
may also be guided from the fluid to the spectrometer located
outside the well. Most preferably, the measurement is conducted on
the fluid without first sampling the fluid. During sampling, the
fluid is necessarily transported and disturbed. By measuring the
fluid outside of an instrument package and in-situ the resultant
concentration or Partial pressure is more accurate.
Other objects, advantages and novel features of the present
invention will become apparent from the following detailed
description of the invention when considered in conjunction with
the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
To further clarify the above and other advantages and features of
the present invention, a more particular description of the
invention will be rendered by reference to specific embodiments
thereof which are illustrated in the appended drawings. It is
appreciated that these drawings depict only typical embodiments of
the invention and are therefore not to be considered limiting of
its scope. The invention will be described and explained with
additional specificity and detail through the use of the
accompanying drawings in which:
FIG. 1 shows a completed coalbed methane wellbore;
FIG. 2 shows a diagram of an isotherm calculation based on a gas
content;
FIG. 3 shows a diagram of the coal bed-reservoir fluid system in
equilibrium;
FIG. 4 shows a graph of a dewatering measurement;
FIG. 5 shows a process diagram of the measurement system;
FIG. 6 shows a graph of a spectral signature for methane at three
different concentrations;
FIG. 7 shows a graph of a calibration between signal to methane
concentration;
FIG. 8 shows a graph of a relationship between dissolved methane
concentration and partial pressure of methane in a reservoir
fluid;
FIG. 9 shows a graphical representation of the relationship between
methane partial pressure and coal gas content;
FIG. 10 shows a representation of a wellbore with concentrations
plotted;
FIG. 11 shows a graph of a measurement when pumping is changed;
FIG. 12 shows a diagram of an isotherm calculation based on a
critical pressure;
FIG. 13 shows a graph of multiple tests for various wells as
plotted on an isotherm;
FIG. 14 shows a flow chart of measurements for a spectrometer;
FIG. 15 shows an averaged coal isotherm; and
FIG. 16 shows a diagram of a measuring device.
DETAILED DESCRIPTION OF THE DRAWINGS
In the following description, numerous specific details are set
forth in order to provide a thorough understanding of the present
invention. It will be obvious, however, to one skilled in the art
that the present invention may be practiced without these specific
details. In other instances, well-known aspects of various items
such as coal bed methane wells and optical scanning systems have
not been described in particular detail in order to avoid
unnecessarily obscuring the present invention.
Reference will now be made to the drawings to describe various
aspects of exemplary embodiments of the invention. It is to be
understood that the drawings are diagrammatic and schematic
representations of such exemplary embodiments, and are not limiting
of the present invention, nor are they necessarily drawn to
scale.
While the following description is directed to coal bed methane
wells, it should not be seen as limiting the scope of the invention
thereto.
As seen in FIG. 3, the methane present in the coal bed is
interrelated to the methane of the reservoir fluid which in turn is
interrelated to the methane present in the well fluid. As the
pressure is reduced on the well fluid, the pressure is in turn
reduced on reservoir fluid and in turn reduced on the coal
reservoir. Under some conditions, the coal reservoir, reservoir
fluid and well fluid are initially at equilibrium. When one of
these is changed the others are affected. The changes are not
instantaneous. For example, a reduction of the pressure in the well
fluid propagates from the well into the coal reservoir first
affecting the pressure of the reservoir fluid and then the pressure
of the coal reservoir. The propagation of the change, whether it is
pressure, concentration of a substance or the like, may depend on
many factors including the fluids, the coal reservoirs,
permeability, porosity, density and cleating of the coal. However,
given time the change propagates as the system moves toward
equilibrium by affecting the coal reservoir, reservoir fluid and
well fluid properties.
When the methane present in the well fluid, reservoir fluid and
coal reservoir are at equilibrium, these quantities are
interrelated and a measurement of one can be correlated into a
measurement of all of them. As the fluid pressure is decreased in
the wellbore fluid, the fluid pressure of the reservoir fluid is
reduced and the pressure of the coal reservoir is reduced. In
response to this pressure reduction, in most instances, the
reservoir fluid simply flows into the wellbore and becomes wellbore
fluid as the two are hydrologically connected. As the surrounding
fluid pressure of the coal reservoir is reduced the coal reservoir
seeks the new equilibrium and intra coal seam fluid flow occurs.
When the pressure of the coal reservoir reaches the critical
desorption pressure, methane gas begins to flow from the coal
itself. This process is what occurs when the well is dewatered by
pumping wellbore fluid. The water level or head is reduced so that
the pressure is reduced and gas is produced.
During drilling the water or fluids are disturbed and mixed with
other strata fluids. Given time the fluid or fluids come into
equilibrium with each other and the reservoirs of the well.
In some cases, the partial pressure of methane may be reduced in
wellbore fluids by intermingling with other fluids. In some cases
the equilibrium between the methane adsorbed on the coal and the
partial pressure of methane in the reservoir fluid may be affected
by introduction of another gas or other material that displaces the
methane from the coal. This production enhancement method can
affect the required completion and production conditions.
The wellbore and reservoir as seen in FIG. 3 fluids have an effect
on each other as well as on the coal reservoir. A concentration of
a substance in the fluid, a pressure or other variable can locally
change for the well fluid. This in turn affects the reservoir fluid
and the coal reservoir. The change propagates into the reservoir
fluid and coal, and the system responds by seeking to reestablish
equilibrium. When a continuous change is effected, such as when the
well is continuously dewatered, a flux or gradient develops between
the well fluid and the reservoir fluid and coal. If the variables
of the change, such as permeability, rate of dewatering, rate of
pressure change or other variables, are known then the
concentration, pressure or the like may be calculated for a given
point within the reservoir fluid or coal. This calculation may
assist in determining the characteristics of the reservoir based
upon a measurement of the well fluid when the well fluid is out of
equilibrium with the reservoir. Thus, a measurement of the gas
content or critical pressure of the methane for the coal reservoir
may be calculated during dewatering, i.e. under non-equilibrium
conditions. A computer model may be used to determine the flux or
difference in concentration or pressure as well as measurements of
other variables such as the porosity, flow characteristics or other
flux variables present in the well and reservoir.
In the case of methane in coalbed reservoir fluids, the partial
pressure of methane is directly affected by the amount of methane
contained or present in the coal bed reservoir and by the ease with
which that methane can adsorb, absorb or otherwise be contained
within the coal. For a given coal, the more methane that is present
in the coalbed reservoir, then the higher the partial pressure of
methane in the fluids. Thus, the partial pressure of methane in the
reservoir fluid is directly related to the amount of methane in the
coal reservoir. As the fluid pressure is reduced as with dewatering
a well, reservoir fluid is transported from the coal reservoir to
the wellbore. Once the partial pressure of methane at the depth of
the coal seam equals the total fluid pressure, any further
reduction in pressure causes the methane to transport off of or out
of the coal reservoir as gas. An example of this is when dewatering
causes the overall reservoir pressure to be lowered below the
critical desorption pressure in a coalbed natural gas well and gas
production to commence.
Therefore, by determining a partial pressure of methane in the
reservoir fluid the critical desorption pressure can be determined.
As the partial pressure of methane is dependent on the amount of
methane in the coal reservoir the partial pressure of methane does
not significantly change for a system at equilibrium. The partial
pressure of methane in the coal reservoir fluid remains constant as
long as the fluid pressure is above the critical desorption
pressure. This constancy of the methane partial pressure in the
coal reservoir fluid can be observed, for example during a
dewatering process when the hydrostatic pressure on the fluid is
being continuously reduced. Thus, the partial pressure of methane
of the reservoir fluid is the critical desorption pressure for the
coalbed reservoir.
As the partial pressure of methane of the reservoir fluid is
interrelated to the partial pressure of methane of the well fluid,
by measuring the partial pressure of methane of the well fluid the
critical desorption pressure can be determined. This, in turn,
given an isotherm of the coal, can establish the coal gas content
of the coalbed reservoir as well as dewatering time, given the rate
of pressure change, and can also provide an estimation of the
methane reserves within the coal reservoir. As shown in FIG. 4 the
total reservoir pressure over time during dewatering may be plotted
based on a linear or fitted curve and compared against the methane
partial pressure. The dewatering time may then be determined.
Direct measurement of the partial pressure of the methane in the
fluid or fluids can be made by a METS sensor or a total gas
pressure sensor with an appropriate filter. A measurement of a
substance which is indicative of the methane partial pressure may
also be used such as carbon dioxide or nitrogen or other substances
which chemically or physically interact with the methane in the
reservoir.
Another way of determining the partial pressure is by direct
physical observation of the fluid in the well. In a wellbore,
fluids near the bottom of the well can contain higher
concentrations of methane and fluids near the top of the well can
contain lower concentrations of methane. In other words, the
saturation limit of methane in water increases with increasing
pressure, which increases with increasing water head or depth. For
a wellbore fluid that contains dissolved methane, that methane will
remain dissolved at depths where its concentration is lower that
the saturation concentration and will cavitate as gas bubbles, to
some extent, at depths where its concentration is higher than the
saturation concentration. The depth at which cavitation commences
is that depth at which the water head pressure is equal to the
methane partial pressure. At depths above this point, the methane
partial pressure exceeds the water head pressure and cavitation
occurs. At depths below this point, the methane partial pressure is
less that the water head pressure and cavitation does not occur. By
observing the depth at which cavitation occurs, it is possible to
calculate the partial pressure of methane in the wellbore fluid.
Due to the well water being saturated with methane at every depth
above that point, the well water will cavitate or form bubbles of
methane at those depths. A video camera, acoustic device, bubble
counter, thermocouple or other transducer of the lice which is
sensitive to the presence or evolution of bubbles in a fluid may be
used to observe the depth at which the water head pressure is equal
to the methane partial pressure. The pressure at this depth is then
equal to the partial pressure of methane within the system or well
fluid at the coal seam. This method of determining the partial
pressure has several drawbacks in that other gases could be
cavitating which would affect the observation and other dynamics of
the well could offset the determination. In addition,
supersaturation and nucleation effects in the fluid can introduce
errors into the determination of the cavitation commencement depth.
Another approach to determining cavitation is to use an optical
spectrometer that can differentiate between the spectroscopic
signature of methane dissolved in water and the gas phase methane
in the bubbles. The difference in spectroscopic signature
frequently manifests as a shift in the absorption peak or Raman
scattering peak for methane or other gases indicative of methane,
as well as changes in the width of such peaks. This method does not
suffer from all of the drawbacks listed above, only the effects of
supersaturation and nucleation, as well as dynamics of the
well.
Another way of determining the partial pressure of methane within
the system or well fluid is by capping the well and allowing the
system to reach equilibrium. The capped well produces gaseous
methane which fills the headspace of the well along with other
gases. These other gases can be water vapor, carbon dioxide or
other reservoir gases. By measuring the pressure of the head space
the total pressure of the gases is obtained. Within this total
pressure the partial pressure of the methane is included. If the
other reservoir gases are subtracted out, by measurement or by
assumption, or assumed to be near zero, then the resultant pressure
is the partial pressure of the methane As this partial pressure of
methane would be the partial pressure of methane in the system the
critical desorption pressure would be known. This method is similar
to a sipper tube or canister which draws in well fluid or reservoir
fluid and is taken out of the well for analysis of the partial
pressure of the methane in a similar manner.
In such cases a sample of the reservoir fluid under reservoir
pressure and temperature conditions in a sealed vessel or in a tube
or other conveyance in which pressure is controlled--i.e. either
maintained as constant or varied in a known and reproducible
manner--is collected. The sample is allowed to come to equilibrium,
or a relationship between the sample state and equilibrium is
determined or estimated. The pressure of the vessel is measured,
and the fraction of that pressure which is due to the gas or gases
of interest is measured or assumed. From those quantities, the
partial pressure of the gas or gases of interest is calculated
Another example uses a sample collected and handled as above, in
which localized, microscopic or macroscopic changes in vessel
pressure are induced in order to induce gas evolution from the
fluid. The system is allowed to come to equilibrium, or a
relationship between the system state and equilibrium is
determined. The pressure of the vessel is measured, and the
fraction of that pressure which is due to the gas or gases of
interest is measured or assumed. From those quantities, the partial
pressure of the gas or gases of interest is calculated. This method
has several drawbacks in that other gases including water vapor
interfere with the measurement and creates uncertainty. The
assumptions associated herewith as well as the necessity of having
equilibrium in the well and fluid collection make this method
undesirable.
Another example of determining the partial pressure directly is to
submerge a vessel with a known volume, containing known or assumed
fluids or gases and equipped with a gas-permeable membrane, into
reservoir fluid or a wellbore, and the dissolved gases in the water
are allowed to equilibrate with fluid(s) and/or gas(es) in the
headspace, then the gas partial pressure in the headspace is
measured with a pressure transducer or other transducer sensitive
to the pressure, activity, fugacity or concentration of the gas or
gases of interest. This can be combined with a sensor that
identifies the fraction of the headspace volume (and thus partial
pressure) that is due to the gas or gases of interest.
The fluid within the well may also be physically altered. In one
example of this method to determine the partial pressure one may
stimulate cavitation in a reservoir fluid using a source of energy
such as a sonic gun or the like and correlate the extent of
cavitation as a function of energy to the partial pressure of the
gas or gases of interest. In another example of this method, the
reservoir fluid may be heated using a variety of heating devices,
including immersion heaters, microwave generators, or injection of
steam of other hot fluids into a device, pipe or other container in
contact with the fluid. The resulting increase in temperature will
reduce the solubility of the methane in the fluid. The correlation
of cavitation to heat input and/or temperature rise can be
correlated to the partial pressure.
Of course another substance's concentration besides methane can
also be measured to determine its partial pressure within the
system. With this method the system should be at or near physical
and chemical equilibrium in order to determine the partial pressure
as it is at or in the coalbed reservoir.
Another example of a method of directly determining the partial
pressure is to retrieve a volume of coal from the coal seam and
seal the sample in a container at the reservoir conditions. This
sample can then be allowed to off-gas methane in a sealed volume.
When the sample comes to equilibrium the pressure in the sealed
volume is the partial pressure of methane in the coal. This method
is problematic in that retrieval of a sample without affecting the
methane partial pressure of that sample is difficult.
Another determination of the partial pressure of methane in the
fluid or fluids may be made by measuring the concentration of
methane or other substance indicative thereof. As seen in FIG. 5
the following example is directed toward a method involving
measuring a concentration of the methane in order to determine the
partial pressure of the reservoir fluid and in turn to determine
production factors, but should not be considered as limiting the
method or apparatus.
A method of certain preferred embodiments of the invention involves
measuring a concentration of methane dissolved in a coalbed
reservoir fluid, correlating that concentration to a partial
pressure of methane in the fluid, correlating that partial pressure
to the partial pressure of methane in the reservoir, and
correlating that partial pressure of methane in the reservoir to a
gas content in the coal as well as determining other production
factors.
For example, FIG. 6 shows the Raman spectral signature of methane
dissolved in water for three different samples having different
methane concentrations.
By correlating the signals measured for a series of samples with
the concentrations of methane dissolved in the samples, it is
possible to create a calibration between signal and concentration.
FIG. 7 shows such a calibration for Raman signal responses to
methane dissolved in water.
Dissolved methane concentration can then be calibrated to partial
pressure of the methane in the reservoir fluid. For ideal fluids
and conditions, this relationship is typically a simple linear
relationship. For less than ideal fluids, or less than ideal
conditions, this relationship may be complex. This relationship can
be established for any fluid or condition by preparing samples of
reservoir fluids under reservoir conditions, by impinging a partial
pressure of methane onto the sample until the system is at
equilibrium and by then measuring the concentration of methane.
This process can be repeated for more than one partial pressure of
methane until a relationship between dissolved methane
concentration and partial pressure is established. Typically, the
partial pressures impinged would be of magnitudes that include the
partial pressure magnitude expected in the reservoir.
For example, a relationship between dissolved methane concentration
and partial pressure of methane typical of some coal seam reservoir
fluids and coal seam reservoir conditions is shown in FIG. 8.
The methane partial pressure in a reservoir fluid can thus be
determined by measurement of the dissolved methane concentration in
that fluid.
The methane partial pressure in a reservoir fluid can then be used
to determine the methane partial pressure in an overall reservoir.
Under typical reservoir conditions, for fluids that are in
physicochemical equilibrium with the reservoir, the methane partial
pressure in a reservoir fluid or well fluid is equal to the methane
partial pressure in the overall reservoir. For fluids that are not
in physicochemical equilibrium with the overall reservoir, one may
correct the partial pressure to reflect that state.
The methane partial pressure in a reservoir can then be used to
determine the gas content of a coalbed reservoir. FIG. 9 shows such
a relationship typical of coal.
Thus, measurement of the concentration of methane dissolved in a
coalbed reservoir fluid can be used to analyze quantitatively the
gas content of the coal.
Another way of performing certain preferred embodiments of the
invention are to measure the concentration of methane in the well
at varying depths. This results in a plot of the concentration of
methane versus the depth as shown in FIG. 10. The concentration of
methane is shown plotted with Henry's law (solid line), or other
models of the saturation limit of methane in water, against depth.
As depth is increased, the measured concentration is saturated to a
certain point A. At this point the concentration of methane in the
water deviates from the saturation curve. This deviation point is
indicative of the partial pressure of methane in the well fluid.
The partial pressure of the methane in the well fluid is the head
or pressure of the water at the deviation point. As the
concentration of methane in a well does not change below the
deviation point when the coalbed reservoir is not off-gassing, even
one methane concentration measurement below the deviation point can
determine the partial pressure of methane by correlation to Henry's
law or a saturation curve. With reference to the discussion above,
cavitation would occur in such a well at any location in the well
bore fluid above Point A.
Other measurements made in a wellbore or on wellbore fluids or
gases can be combined with the methane concentration to provide a
detailed understanding of the coal seam reservoir properties and
stage of production. This process can include measurement and/or
analysis of reservoir pressure, reservoir temperature, ionic
strength of reservoir fluids, saturation limit of methane dissolved
in water under reservoir conditions, depth and thickness of coal
seams, coal rank, coal thickness, coal ash content, coal masceral
content, wellbore diameter, wellbore total depth, casing size,
casing type, cement type, cement volume used, perforation
locations, perforation sizes, perforation hole density, historical
water production volumes and rates, historical gas production
volumes and rates, completion and production methodology, cone of
depression, reservoir models, well structures, and other relevant
variables.
Measurement of the dissolved methane concentration in a reservoir
fluid can occur using a number of different methods and
apparatus.
Measurements can be made downhole in a well that is drilled into a
reservoir, and manipulated to contain the reservoir fluid. Such
measurements can be made using an optical spectrometer, such as a
Raman spectrometer. Such measurements can be made using a
membrane-coated semiconductor sensor. Such measurements can be made
using a mass spectrometer. Such measurements can be made using a
sensor such as an optical spectrometer in tandem with a sample
collector such as a formation tester or with a fluid control system
such as a coiled tubing pump system. Such measurements can be made
using a nuclear magnetic resonance spectrometer or a radio
frequency, acoustic frequency, or microwave frequency spectrometer.
Such measurements can be made using any transducer or sensor that
provides a signal in response to methane concentration, including
those transducers and sensors that may be less than quantitative in
signal response.
Measurements can be made at the wellhead in a well that is drilled
into a reservoir, and manipulated to contain the reservoir fluid.
Such measurements can be made using standard laboratory analysis,
e.g. via gas chromatography, on samples collected with various
sampling apparatuses, including vessels that allow fluids of
interest to flow into them and then seal, on samples that are
collected at the wellhead using a pressure-regulated pumping
system, and on other samples collected using methods obvious to
those skilled in the art.
In some cases, fluids in a wellbore are not representative of a
reservoir. For example, a wellbore drilled into more than one coal
seam may contain commingled fluids that are representative of both
reservoirs, in some ratio. In these cases, concentration
measurements can likewise reflect the properties of both
reservoirs, in some ratio.
Wellbores and wellbore fluids can be manipulated in order to ensure
that the wellbore fluid properties, most specifically the methane
concentration but also the temperature, pressure, ionic strength,
and/or other physicochemical properties, reflect the reservoir
properties of interest. For example, wells can be completed in only
one coal seam so that other coal seams or geologic intervals cannot
contribute fluids to the wellbore. In another example, the wellbore
fluids in a well drilled into a coal seam can be allowed to
equilibrate with the coal seam reservoir until the wellbore fluids
reflect the properties of the coal seam reservoir. In another
example, the wellbore fluids can be extracted from the wellbore in
order to induce fluid flow from the reservoir into the wellbore
until the wellbore fluids reflect the properties of the reservoir
of interest. In another example, multiple coal seams in a well can
be isolated using bridge plugs, packers, or other such apparatuses.
The wellbore fluids in the isolated regions can then be allowed to
equilibrate with the associated coal seam reservoirs, or one or
more isolated regions can be evacuated with pumps or other
mechanisms in order to induce fluid flow from the coal seam into
the isolated regions until the fluids in the isolated regions
reflect the coal seam reservoir properties of interest.
To manipulate wellbore fluids, the aforementioned formation tester,
or other packer/pump assembly, can be used to extract fluid from
the sidewall of a well until the fluid extracted represents the
desired reservoir property. In one case, this could involve using
the formation tester to extract fluid from one coal seam, in a
wellbore that contains fluids commingled from more than one coal
seam, until the fluid contained in the formation tester reflects
only the properties of that one coal seam reservoir. Then, the
concentration measurement could be performed on that sample either
at the surface or in the well.
Fluid manipulations can be used to draw fluids from various places
in a reservoir, and thus provide the opportunity to analyze the
properties of those places without drilling a well to them. For
example, key reservoir variables of a coal seam near a wellbore can
be analyzed by measuring the methane concentration and other
properties of a wellbore fluid. The wellbore fluid can then be
removed from the wellbore so that additional fluids flow from the
coal seam into the wellbore. At some established time, the wellbore
fluids can again be analyzed with the expectation that the fluids
reflect the properties of the reservoir farther from the wellbore.
In another example, a portion of the sidewall can be covered so
that fluid is removed from the surrounding coal reservoir in only
one cardinal direction. Thus, the rate of fluid removal, and the
properties of the fluid and substances that it contains, can
indicate reservoir properties of interest such as clearing
orientation, fracturing orientation, and dewatering and production
volume aspect ratio.
In one example of this technique, for a producing well that
establishes a cone of depression near a wellbore, when the pump in
that well is turned off the fluids from the surrounding coal
reservoir flow into the wellbore. Near the wellbore, those fluids
may be saturated in methane due to depressurization of the
wellbore. Farther from the wellbore, those fluids may not be
saturated because the cone of depression does not reach their
region. By analyzing the methane concentration as a function of
flow time, the cone of depression extent can be ascertained. This
extent can be used to draw conclusions regarding whether the coal
seam is being effectively depressurized and for how long the coal
will produce gas at that pressure. As shown in FIG. 11 the Henry's
law saturation curve during pumping is represented (solid line) as
well as the saturation curve for when the pump is turned off (gray
line). By measuring concentrations of methane (solid circles) after
the pump is turned off and plotting against the saturation curves,
the relation between the curves and the concentrations show how
effective the well is being produced as well as indicating the
slope of the cone of depression, and thus dewatering time and
permeability. Concentrations of methane near the pump off curve
indicate that the well is being produced effectively and that
dewatering time has been long and/or permeability is high as well
as a very small cone of depression. Concentrations close to the
saturation curve for when the pump is on indicate that the cone of
depression may be large and dewatering time has been short and/or
permeability is low.
In some instances one coal seam can be extremely large. Some seams
may be 100 feet or larger in thickness. By measuring at different
places along the coal seam the resultant partial pressures may be
used to identify and determine production factors that may not be
representative of one measurement. A cone of depression may
actually be able to be identified if the cone of depression has
vertical stratification along the seam. Other variables for the
seam may also be determined via measuring along the entire
width.
Measuring the methane concentration in a reservoir fluid, and
analysis of other reservoir properties, thus allows analysis of
critical desorption pressure, dewatering time and volumes, and
other key reservoir and operating variables.
For example, FIG. 12 represents a map of gas content and total
reservoir pressure. The line indicates where in that space the coal
gas content is saturated. Measurement of methane concentration, and
thus gas content, for a coal at a certain reservoir pressure allows
mapping of that particular reservoir onto this space. Reservoirs
that adhere to the saturation line contain coals saturated with
gas. Reservoirs that do not adhere to the saturation line contain
coals that are undersaturated with gas.
Point A indicates an example reservoir that is undersaturated with
gas. In order for gas to be produced from that coal, the overall
pressure must be reduced until equal to the methane partial
pressure, termed the critical desorption pressure. Thus,
measurement of dissolved methane concentration allows direct
quantitative analysis of critical desorption pressure.
Further analysis is possible using this type of map. FIG. 2 shows
some examples. By determining the pressure at the coal seam the
saturation of the coal can be determined with reference to the
isotherm. The gas recovery factor may also be determined by
determining the abandonment pressure and correlating to the
isotherm then calculating the recovery factor based upon the
critical desorption pressure.
By measuring methane concentration in more than one wellbore, it is
possible to map more than one reservoir area (or more than one coal
seam) onto a coal gas content versus pressure map as shown in FIG.
13. By doing so, it is possible to determine which coal seams will
provide the most gas production in the least amount of time and/or
with the least amount of water production.
In some cases, the saturation line is the same or nearly the same
for more than one area of coal or more than one coal seam, allowing
direct comparisons to be made. In other cases, the saturation line
must be measured, e.g. by adsorption isotherm analysis of cuttings,
in order to allow comparison.
Conversion of a Raman spectrum of coal bed fluid to a gas content
is based on scientific principles. An exemplary conversion process
is summarized below and shown in FIG. 14. First Raman measurements
are taken as well. Temperature, pressure, and conductivity are also
measured or provided. In one embodiment and as described elsewhere
herein, using this data the Raman spectra measurements are analyzed
to determine methane concentration data, which are in turn analyzed
to determine methane partial pressure data. Alternatively, as also
described elsewhere herein, the Raman spectra can also in some
instances be converted directly the methane partial pressure data.
The methane partial pressure data is then analyzed along with coal
isotherm data to determine the coal gas content.
Working in reverse order, to calculate the gas content, the partial
pressure of methane in the fluid surrounding the coal and the
isotherm of the coal are provided. The isotherm is a correlation,
at a given temperature, between the partial pressure of methane and
the storage capacity of the coal, i.e. saturated methane gas
content. The isotherm should be known or estimated externally to
the Raman measurement. Thus, the goal in making the Raman
measurement is to determine the partial pressure of methane in the
fluid surrounding the coal.
In order to make this conversion between a Raman spectrum and
methane partial pressure, the instrument is calibrated. This is
done by one of two methods. Both involve preparing samples of
methane in equilibrium with water at various pressures. Raman
spectra of the samples are taken. The pressures of the samples
should correlate with the range of methane partial pressures
expected in the unknown samples.
The concentration of methane in each sample's fluid can be
calculated by Henry's law, using an appropriate Henry's law
constant for the given conditions, i.e. temperature, salinity and
methane partial pressure, or by some other method that indicates
the solubility of methane in water. This methane in fluid
concentration can then be correlated with the intensity of the
methane peak in the Raman spectra of the sample. This method is
robust and has several advantages.
Alternately, the partial pressure of methane can also be directly
correlated with the intensity of the methane peak in the Raman
spectra.
With the above correlations, either methane concentration or
partial pressure can be calculated by measuring the Raman spectrum
of an unknown sample. Correlating directly to partial pressure,
while simpler, introduces a larger possibility for error, as the
unknown fluid may not have the same relationship between dissolved
methane and partial pressure, i.e. Henry's law constant (or other
solubility relationship). Conversely, correlating to concentration
and then to partial pressure provides the advantage that the
relationship between concentration and Raman signal will not be
affected by differences in the fluid quality, without it being
obvious in the Raman spectra, example: an unknown peak in the same
spectral range as the methane. Subsequent conversion of methane
concentration to partial pressure uses Henry's law and a Henry's
law constant that is corrected for the unknown sample's temperature
and salinity, which can be measured in a wellbore, for example. In
both of these methods the partial pressure of methane is
calculated. This then allows a direct reading from the isotherm (as
shown in FIGS. 2 and 12) to determine the gas content.
Many factors such as localized depressurization may be taken into
account when determining the partial pressure.
Another example of the steps to determine the partial pressure
based upon an optical measurement of the methane concentration to
reach partial pressure is as follows. First, construct a
calibration of Raman or other spectrometer counts that relates
those counts to methane concentration dissolved in water
(preferably, an ideal water such as deionized water). This requires
that one first apply a methane partial pressure at a room
temperature and allow the system to come to equilibrium; preferably
this is done for a pressure range that exceeds the range of
interest in the well. Then, one measures the Raman signal from the
methane in the ideal water sample and calculates the methane
concentration dissolved in that sample. Then, one can correlate
this concentration with the methane partial pressure that was
applied, using a Henry's law constant for water at room
temperature. This gives a calibration between Raman signal,
concentration in the water and partial pressure of methane above
the water at room temperature.
The function is: moles of CH.sub.4/moles of
water=Pressure[atm]*Henry's constant [mM]
CH.sub.4=Pressure[atm]*Henry's constant*55 moles of water/liter
water*1000
Second, record the Raman spectra of the unknown well sample, and
its temperature and salinity.
Third, from the Raman measurement and the calibration, a
concentration of the methane in the well water is calculated, via
computer or model.
Fourth, with the methane concentration and a value of the Henry's
law constant for the particular well temperature and salinity,
calculate a methane equilibrium partial pressure. Values of Henry's
law constant for temperatures and salinities of interest are
available in published literature, or can be measured in the
laboratory.
Fifth, obtain or generate a relationship between saturated coal gas
content at the reservoir temperature versus methane partial
pressure, where the coal is in a saturated moisture state, i.e. at
its equilibrium moisture content. This can be a general isotherm
for the type of coal or for more accuracy, the exact coal from the
well.
Sixth, using the equilibrium methane partial pressure for the well
conditions (methane content, temperature and salinity), calculate a
gas content for the coal from the isotherm. With a valid isotherm
for the coal, the methane content of the coal can be read off the
isotherm with the partial pressure of methane. Another option is to
use a Langmuir or other type of isotherm model equation to
represent the true isotherm. The Langmuir and other model equations
are equation versions of the isotherm. Using these one can
calculate the gas content with the equation. Lastly, the accuracy
of the values used for the Henry's law constant and the coal
isotherm will have an effect on the accuracy of the
calculations.
As described above, by measuring the partial pressure of methane or
another indicative substance or by correlating the concentration of
methane to partial pressure a production value can be obtained. The
use of an ideal gas content curve or coal isotherm is needed in
order to determine the coal gas content. As mentioned earlier a
cutting or core sample of the coal may be used to determine the
actual coal isotherm. However, an isotherm from a similar coal or
coal type may be used as well as an isotherm which is
representative of a coal, coal type, coal formation or coal
basin/region. In such an instance a library of coals may be
compiled in order to allow automated determinations based on the
coal. This may result in a range of values dependent on the
isotherms used. Another example of automating the determination of
the coal gas content is by using a model based upon equations.
Below is a method of determining the gas content from the partial
pressure of methane via an isotherm model for a wide range of
coals. In this model the actual coal isotherm for the coal being
measured need not be measured. However, to achieve a more accurate
gas content an actual cutting or core and measurement of the coal
can be done to determine the isotherm for the specific coal
bed.
The correlation goes from Pm (methane partial pressure, which is
obtained from the methane concentration and the appropriate value
of the Henry's law constant) to G (coal gas content).
The Langmuir equation is: .theta./(1-.theta.)=Ka; where .theta. is
fractional gas coverage or gas content (i.e. .theta.=G/G.sub.sat
with G.sub.sat=G at saturation, in scf/ton), K is the binding
constant for methane to the coal and a is thermodynamic activity,
which is related to concentration and to "partial pressure of
methane," P.sub.m.
By analogy, a new Langmuir isotherm is defined:
G.sub.sat{.theta./1-.theta.}=K.sub.bP.sub.m where, K.sub.b is the
binding constant for methane to the coal in scf/ton psi. This
formulation has G approaching G.sub.sat as P.sub.m goes to
infinity. Now, using .theta.=G/G.sub.sat
G/{1-(G/G.sub.sat)}=K.sub.bP.sub.m;
G=K.sub.bP.sub.m-{GK.sub.bP.sub.m/G.sub.sat};
G{1+(KbP.sub.m/G.sub.sat)}=K.sub.bP.sub.m And finally,
G=(K.sub.bP.sub.m)/{1+(K.sub.bP.sub.m/G.sub.sat)} Equation 1
With this comes G (coal gas content) from K.sub.b and P.sub.m. The
linearized reciprocal equation is: 1/G=1/K.sub.bP.sub.m+1/G.sub.sat
Equation 2
This linearized reciprocal equation was used to analyze the
isotherm shown in FIG. 15 below (i.e. plot 1/G versus 1/P, which
gives 1/G.sub.sat as the intercept and 1/K.sub.b for the slope).
This gives an R value of 0.99953. It gives G.sub.sat=178 scf/ton
and Kb=0.175 scf/ton psi.
Using Equation 1 above with these values, one can enter any value
of P.sub.m and obtain the corresponding value of G for coals for
which the typical isotherm in FIG. 15 is suitable. To predict the
isotherm a bit more closely reiterations and other modifications
can be done.
Methods of directly determining or measuring amount of gas in a
coal seam or region of a coal seam can include, but are not limited
to, spectroscopies in which energy travels into the coal seam and
interacts with methane or substances indicative of the amount of
methane. Examples include acoustic spectroscopy, microwave
spectroscopy, ultrasonic spectroscopy, reflectometry, and the like.
In an example case, microwave radiation of the appropriate
wavelength is impinged on a coal seam, travels through the coal
seam to an extent that allows sufficient interaction with methane,
and a method of detection based on that interaction that provides
the amount of methane entrained in the coal seam is used. That
amount of methane is related to the gas content of the coal
seam.
The apparatus to carry out certain preferred embodiments of the
invention includes as shown in FIG. 16 a partial pressure sensor or
measuring device and a comparator for comparing the methane partial
pressure to the isotherm. In one embodiment the partial pressure
measuring device includes a concentration measuring device and a
calibration system to calibrate the concentration of dissolved
methane to the partial pressure. The apparatus may include other
sensors such as a temperature sensor, salinity sensor and/or a
pressure sensor. The measurements for each of these may be used by
the calibration system in order to determine the methane partial
pressure.
In a preferred embodiment shown in FIG. 16, a coal bed methane well
1 with a borehole 3 extends from a well head to a coal seam 10 with
a side surface 11 and an aquifer fed water level 9. A Raman
spectrometer 4 is located at surface 2 at or near the wellhead and
includes a radiation source 5 for producing a radiation to transmit
down the borehole 3 to a sample interface 17. The radiation from
the radiation source is transmitted by way of at least one optical
pathway 7. The sample, in this case being water, interacts with the
radiation transmitted from the radiation source 5, and a
characteristic radiation for the sample is produced by the
interaction. The characteristic radiation is then transmitted by an
optical pathway 7 to a detector 6 located in the spectrometer 4 at
the surface. A suitable optical pathway 7 for transmission is
optical fiber 8. The system used to measure the concentration may
also contain other measuring devices for salinity or electrical
conductivity as well as temperature and pressure. Preferably, the
system will measure the temperature and the electrical conductivity
of the reservoir fluid with the concentration. This will allow a
more accurate determination of the methane partial pressure in the
reservoir fluid
The optical fiber 8 extends down the borehole 3 to the housing 12
and feeds into the housing through a high-pressure feed-through
jacket 18. The jacket 18 allows the fiber 8 to enter the housing 12
without subjecting the housing to the conditions down the well,
such as high pressure, particles and the water. The housing
protects any filter 14 or other instrumentation enclosed by the
housing. The fiber 8 may extend out of the housing through another
jacket 18 to optically couple the sample or substance of interest.
A tip 15 of the fiber 8 supplies the radiation from the radiation
source 5 and collects the characteristic radiation. A system which
includes a concentration sensor for use downhole may be preferable
due to its size and speed. An optical instrument for use down a
well is comprised of a radiation source which is directed through a
series of optical components to a sampling interface where the
radiation interacts with a sample that is outside of the instrument
and across this interface. The returning radiation is then directed
through a series of optical components to a spectrometer. A
controlling device inputs operating parameters for the spectrometer
and packages spectral data for delivery to an uphole computer. The
entire instrument is packaged in a steel housing, with additional
sensors for pressure, temperature, and conductivity incorporated
into the housing endcap. The instrument is attached to a cable head
and lowered into a wellbore by a wireline winch. The uphole
computer and software allows a user to set operating parameters for
the instrument and graphically display data delivered from the
controlling device.
The optical fiber 8 may be a bundle of fibers where the center
fiber transmits the radiation from the radiation source 5 and the
other fibers transmit the characteristic radiation. A single
collection fiber for the characteristic radiation may also be used.
The fiber 8 may also include a lens. The fibers use a polished tip
or fused tip. A calibration file is created by correlating response
and spectra of dissolved methane to known concentrations of
dissolve methane. The calibration file is used to predict methane
concentration from the spectra delivered uphole by the instrument.
Several additional calibrations are created at various temperatures
and salinities to develop a library of Henry's law constants to be
used in order to calculate methane partial pressure. The values of
temperature and conductivity measured downhole are used to choose
an appropriate Henry's law constant from the library and calculate
a methane equilibrium partial pressure for the reservoir from the
concentration measured by the instrument. This methane equilibrium
partial pressure is a critical desorption pressure. As the total
pressure (hydrostatic pressure) falls below the critical desorption
pressure, the well begins stable gas production.
The sample interface includes an inlet 16 and an outlet 17 for the
water in the well. The water flows into the inlet when the housing
is positioned down the well at a depth and flows around the tip 15
of the fiber to thereby interact with the radiation from the
radiation source 5. Once critical desorption pressure is known for
the reservoir, gas content is calculated using the value for
critical desorption pressure in conjunction with an isotherm that
is representative of the coal's ability to sorb methane. An
isotherm is a plot of total methane pressure with respect to a
coal's holding capacity for methane, in standard cubic feet of gas
per ton of coal. A technique as describe above may be used to
determine an isotherm.
The rate at which the hydrostatic pressure head (water level) can
be lowered depends on the discharge rate of the pump, the well
completion method, relative permeability of the reservoir and
reservoir recharge rate. By noting the static water level before
water discharge begins, one can monitor the hydrostatic pressure
drop with a pressure transducer attached just above the pump and
determine the rate at which the hydrostatic pressure drops with
respect to total water discharge. This rate can be used to predict
the time need to reach the critical desorption pressure of the well
or the dewatering time as described above.
The depletion area of water from the reservoir, or cone of
depression, can be modeled using hydrological assumptions and water
discharge rates to determine the lateral extent of reservoir at or
below the critical desorption pressure and actively contributing to
stable gas production.
As the exemplary descriptions have been used to explain the
invention with regard to coalbed methane they should also be
considered to include the determination with regard to coal shale
and other carbonaceous formations, and they should be considered to
include the determination with regard to carbon dioxide, nitrogen,
other hydrocarbons, and other gases, in addition to the methane as
mentioned. The exemplary descriptions with regard to measuring or
determining concentration and the production factors should also be
considered to include other precursor variables and is not meant to
be limiting.
The present invention may be embodied in other specific forms
without departing from its spirit or essential characteristics. The
described embodiments are to be considered in all respects only as
illustrative and not restrictive. The scope of the invention is,
therefore, indicated by the appended claims rather than by the
foregoing description. All changes which come within the meaning
and range of equivalency of the claims are to be embraced within
their scope.
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